The embodiments herein relate to methods and compositions for treating subterranean formations. More particularly, the embodiments herein relate to treatment fluids comprising low-leakoff particulates comprising polymers and crosslinking agents, and methods of use in subterranean operations.
Treatment fluids may be used in a variety of subterranean treatments, including, but not limited to, stimulation treatments and sand control treatments. As used herein, the term “treatment,” or “treating,” refers to any subterranean operation that uses a fluid in conjunction with a desired function and/or for a desired purpose. The term “treatment,” or “treating,” does not imply any particular action by the fluid or any particular component thereof.
One common production stimulation operation that employs a treatment fluid is hydraulic fracturing. Hydraulic fracturing operations generally involve pumping a treatment fluid (e.g., a fracturing fluid) into a well bore that penetrates a subterranean formation at a sufficient hydraulic pressure to create one or more cracks, or “fractures,” in the subterranean formation. In some cases, hydraulic fracturing can be used to enhance one or more existing fractures. “Enhancing” one or more fractures in a subterranean formation, as that term is used herein, is defined to include the extension or enlargement of one or more natural or previously created fractures in the subterranean formation. The fracturing fluid may comprise particulates, often referred to as “proppant particulates,” that can be deposited in the fractures. The proppant particulates function, inter alia, to prevent the fractures from fully closing upon the release of hydraulic pressure, forming conductive channels through which fluids may flow to the well bore. Once at least one fracture is created and the proppant particulates are substantially in place, the fracturing fluid may be “broken” (i.e., the viscosity of the fluid is reduced), and the fracturing fluid may be recovered from the formation.
Treatment fluids are also utilized in sand control treatments, such as gravel packing. In gravel-packing treatments, a treatment fluid suspends particulates (commonly referred to as “gravel particulates”) to be deposited in a desired area in a well bore, e.g., near unconsolidated or weakly consolidated formation zones, to form a gravel pack to enhance sand control. One common type of gravel-packing operation involves placing a sand control screen in the well bore and packing the annulus between the screen and the well bore with the gravel particulates of a specific size designed to prevent the passage of formation sand. The gravel particulates act, inter alia, to prevent the formation particulates from occluding the screen or migrating with the produced hydrocarbons, and the screen acts, inter alia, to prevent the particulates from entering the production tubing. Once the gravel pack is substantially in place, the viscosity of the treatment fluid may be reduced to allow it to be recovered. In some situations, fracturing and gravel-packing treatments are combined into a single treatment. In such “frac pack” operations, the treatments are generally completed with a gravel pack screen assembly in place with the hydraulic fracturing treatment being pumped through the annular space between the casing and screen. In this situation, the hydraulic fracturing treatment ends in a screen-out condition, creating an annular gravel pack between the screen and casing. In other cases, the fracturing treatment may be performed prior to installing the screen and placing a gravel pack.
Maintaining sufficient viscosity is important in fracturing and sand control treatments for particulate transport and/or to create or enhance fracture width. Also, maintaining sufficient viscosity may be important to control and/or reduce fluid-loss into the formation. At the same time, while maintaining sufficient viscosity of the treatment fluid often is desirable, it may also be desirable to maintain the viscosity of the treatment fluid in such a way that the viscosity also may be easily reduced at a particular time, inter alia, for subsequent recovery of the fluid from the formation.
To provide the desired viscosity, gelling agents commonly are added to the treatment fluids. The term “gelling agent” is defined herein to include any substance that is capable of increasing the viscosity of a fluid, for example, by forming a gel. Examples of commonly used polymeric gelling agents include, but are not limited to, guar gums, derivatives thereof, and the like. To further increase the viscosity of a treatment fluid, often the gelling agent is crosslinked with the use of a crosslinking agent. Conventional crosslinking agents usually comprise a metal ion that interacts with at least two gelling agent molecules to form a crosslink between them, thereby forming a “crosslinked gelling agent.” In some applications, crosslinking agents act within a specific pH range whereby the crosslink that is formed may be reversed by either raising or lowering the pH. When used in some applications such as seawater, the modification of the pH may result in the formation of additional compounds that can be detrimental to the formation such as precipitates produced due to the presence of various ions in seawater.
In addition to those components discussed above, conventional fluid loss additives can be used to prevent or limit the amount of fluid lost to the formation, for example during a hydraulic fracturing operation. Typical fluid loss control additives for stimulation fluids can comprise solids such as ground salt, ground calcium carbonate, starch and the like. In some instances, a gelling agent can act as a fluid loss additive by preventing the flow of the fluid into the subterranean formation. These materials can be difficult to remove from the fractures, particularly after the fracture is propped open by the introduction of a proppant particulates. The presence of unremoved fluid loss additives can result in a significant reduction in the production flow capacity of the fracture. In addition to the reduction in flow capacity, the use of conventional fluid loss additives may increase the complexity and cost of a treatment fluid and/or a subterranean application utilizing that fluid. Moreover, many conventional fluid loss additives permanently reduce the permeability of a subterranean formation, affect the rheology of the treatment fluid in which they are used, and/or reduce the rate at which the fluid is allowed to penetrate or leak off into the subterranean formation. In terms of placing the treatment fluid into the subterranean formation, any attempt to increase the stimulation fluid viscosity to a level whereby fluid loss can be controlled without using significant quantities of particulate fluid loss additives can result in an increase in the friction pressures resulting from the higher viscosity fluid. This may limit the pumping rate and diminish the ability to produce a desired fracture length.
In some instances, while it may be desirable to control or prevent fluid loss for a given period of time, it may become desirable to allow the treatment fluid to penetrate or leak off into the subterranean formation, or to increase the permeability of the subterranean formation, at some later point in time. Costly and time-consuming operations may be required to reverse the effects of conventional fluid loss control additives on the treatment fluid and/or to restore permeability to those portions of the subterranean formation affected by the fluid loss control additives.